Key Reports:

State of the art review of CO2 Storage Site Selection and Characterisation Methods

2.2.2 Hydrocarbon fields

CO2Carbon dioxide storage capacity estimations of European hydrocarbon fields have been carried out in the GESTCO (Schuppers et al., 2003) and the EUEuropean Union GeoCapacity projects (Vangkilde-Pedersen et al., 2008). For all fields, the equivalent of practical or realistic capacity was assessed. These were static capacities estimated on the assumption that the volume occupied by recoverable hydrocarbons (recovery ratio as using standard production technology, without CO2Carbon dioxide injection) in the reservoir can be filled up again by injected carbon dioxide. For a number of case studies, injection scenarios were analysed, and the equivalent of matched or practical capacity was obtained.

Especially in the case of gas fields, the formation factor - i.e. the volume produced gas occupies in the reservoir divided by its volume on at the surface - is essential to provide a reliable estimate of static CO2Carbon dioxide storage capacity (see Fig. 2-7, density of natural gas within the reservoir is 100-300 kg/m³, while at the surface is less than 1 kg/m³).

E. Fig . 2-7

Fig. 2-7: Density variation of natural gas and CO2Carbon dioxide with depth (Schuppers et al., 2003).

The following, simplified formula was used in order to estimate the static capacities of hydrocarbon fields (Schuppers et al., 2003; Tab. 2-5):

M_{CO2Carbon dioxide} = ρ_CO2r × UR_p × B

The capacity can also be calculated using Bachu, 2008 Phase III formula:

M_{CO2Carbon dioxide} = r_CO2r × (R_f × OOIP / B_f - V_iw + V_pw)

where OOIP is original oil in place.

In this last expression, UR_p in fact represents R_f OGIP and R_f OOIP, respectively, but the formula does not take F_ig, V_iw and V_pw into account. UR_p is the sum of the cumulative production and the proven reserves and typically, the methodology for calculating/estimating the proven reserves varies from country to country.

Tab. 2-5: Parameters used in the static capacity assessment of hydrocarbon fields (GESTCO and EUEuropean Union GeoCapacity projects; Schuppers et al., 2003 and Vangkilde-Pedersen et al., 2008).

Parameter	M_{CO2Carbon dioxide}	ρ_CO2r	UR_p	B
Description	Hydrocarbon field storage capacity	CO2Carbon dioxide density at reservoir conditions	Proven ultimate* recoverable oil or gas	Oil or gas formation factor
Typical values	Oil & Gas: Mtonnes to hundreds of Mtonnes	0.6-0.8 g/cm³	Oil - Mm³ (10⁶ m³) to hundreds of Mm³ Gas - Bm³ (10⁹ m³) to hundreds of Bm³	Oil - slightly bigger than 1; Gas - far smaller than 1 (e.g. 0.003-0.007)

*For gas fields in case gas is re-injected the amount shall be extracted from UR_p; Regarding UR_p of oil fields where water is injected and produced the injected one shall decrease and the produced increase UR_p.

The ultimate recoverable oil and gas can be given, on a field by field basis, as the sum of produced volumes and expected reserves, or by applying a fixed conversion factor to the expected ultimate recoverable oil and gas.

The formation volume factor used for oil varies regionally and/or locally depending on the oil type and the formation volume factor used for gas should vary with depth as a function of pressure and temperature. Likewise the CO2Carbon dioxide density should also vary with depth as a function of pressure and temperature. Both may, however, in some countries, have been applied as constant average values to all hydrocarbon fields.

The methodology used for hydrocarbon fields yields theoretical storage capacity, according to the methodology described by Bachu et al., 2007. To reach effective storage capacity, a number of capacity coefficients representing mobility, buoyancy, heterogeneity, water saturation and aquifer strength were introduced, all of which reduce the storage capacity. However, if there are insufficient data for estimating the values of these capacity coefficients, it is not possible to distinguish between theoretical and effective storage capacity for hydrocarbon fields.